Communication to a downhole tool by acoustic waveguide transfer

ABSTRACT

Systems, methods and apparatuses for communication between a surface of a wellbore and a downhole location of a wellbore via acoustic waveguide transfer. A first device can transmit an acoustic signal through a wellbore waveguide that is coupled with the first device. The acoustic signal can transfer from the wellbore waveguide to a wellbore tubular through a contact between the wellbore waveguide and the wellbore tubular. A second device can receive the acoustic signal via the wellbore tubular that is coupled with the second device.

TECHNICAL FIELD

The present technology pertains to telemetry between the surface of awell and a downhole tool, and more specifically to acoustic telemetryusing acoustic waveguide transfer.

BACKGROUND

Modern well operations routinely utilize tubing, such as coiled tubingor jointed tubing, to carry out various well operations. In typicalapplications, the tubing is fed from the surface of a well into awellbore to lower a downhole tool into a desired position. To ensurewell operations are completed in a timely and efficient manner,operators at the surface of the well must remain in communication withthe downhole tool to change the configuration of the downhole tool,verify the functionality of the downhole tool or reset the downholetool, for example. Current communication solutions often require the useof a wired link, such as an electrical conductor or a fiber optic cable,integrated with the tubing to facilitate communication between thesurface of the well and the downhole tool. However, these telemetrysystems are subject to interference caused by the harsh conditionsdownhole and often require long rig-up times. Other systems, such aspressure-pulse telemetry systems, require occupation of the fluid mediumwithin the tubing and can restrict pumping configurations. Thus, areliable wireless telemetry system that does not interrupt welloperations would be advantageous.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and otheradvantages and features of the disclosure can be obtained, a moreparticular description of the principles briefly described above will berendered by reference to specific embodiments thereof which areillustrated in the appended drawings. Understanding that these drawingsdepict only exemplary embodiments of the disclosure and are nottherefore to be considered to be limiting of its scope, the principlesherein are described and explained with additional specificity anddetail through the use of the accompanying drawings in which:

FIG. 1 illustrates a schematic diagram of an example system forcommunication between a surface location and a downhole location byacoustic waveguide transfer;

FIG. 2A illustrates an example of sinusoidal buckling of tubing in awellbore;

FIG. 2B illustrates a cross-sectional view of the sinusoidal buckling inFIG. 2A;

FIG. 2C illustrates an example of helical buckling of tubing in awellbore;

FIG. 2D illustrates a cross-sectional view of the helical buckling inFIG. 2C;

FIG. 3A illustrates a schematic diagram of an example system embodimentfor communication from a surface location to a downhole location;

FIG. 3B illustrates a schematic diagram of an example system embodimentfor communication from a downhole location to a surface location; and

FIGS. 4A and 4B illustrate schematic diagrams of example computingsystems for use with example system embodiments.

DETAILED DESCRIPTION

Various embodiments of the disclosure are discussed in detail below.While specific implementations are discussed, it should be understoodthat this is done for illustration purposes only. A person skilled inthe relevant art will recognize that other components and configurationsmay be used without parting from the spirit and scope of the disclosure.

Additional features and advantages of the disclosure will be set forthin the description which follows, and in part will be obvious from thedescription, or can be learned by practice of the herein disclosedprinciples. The features and advantages of the disclosure can berealized and obtained by means of the instruments and combinationsparticularly pointed out in the appended claims. These and otherfeatures of the disclosure will become more fully apparent from thefollowing description and appended claims, or can be learned by thepractice of the principles set forth herein.

It will be appreciated that for simplicity and clarity of illustration,where appropriate, reference numerals have been repeated among thedifferent figures to indicate corresponding or analogous elements. Inaddition, numerous specific details are set forth in order to provide athorough understanding of the embodiments described herein. However, itwill be understood by those of ordinary skill in the art that theembodiments described herein can be practiced without these specificdetails. In other instances, methods, procedures and components have notbeen described in detail so as not to obscure the related relevantfeature being described. The drawings are not necessarily to scale andthe proportions of certain parts may be exaggerated to better illustratedetails and features. The description is not to be considered aslimiting the scope of the embodiments described herein.

The term “coupled” is defined as connected, whether directly orindirectly through intervening components, and is not necessarilylimited to physical connections. The term “substantially” is defined tobe essentially conforming to the particular dimension, shape or otherword that substantially modifies, such that the component need not beexact. For example, substantially rectangular means that the object inquestion resembles a rectangle, but can have one or more deviations froma true rectangle. The phrase “wellbore tubular” is defined as one ormore types of connected tubulars, and can include, but is not limitedto, tubing, production tubing, jointed tubing, coiled tubing, casings,liners, drill pipe, landing string, combinations thereof, or the like.The term “transceiver” is defined as a combination of atransmitter/receiver in one package but can include a separatetransmitter and a separate receiver in one package or two packages.

The approaches set forth herein can be used for communication between asurface of a wellbore and a downhole location of a wellbore via acousticwaveguide transfer. Subterranean wells can employ wellbore tubulars tocomplete various well operations. During such operations, the wellboretubular can be lowered into, or withdrawn from, the wellbore through aprocess known as “tripping”. However, the dynamic nature of the wellboretubular during tripping can make it difficult to maintain physicalcontact between the wellbore tubular and an acoustic transmitter at thesurface of the wellbore. Furthermore, wellbore casing or productiontubing surrounding the wellbore tubular typically have poor acousticwaveguide characteristics.

Disclosed are systems, methods and apparatuses for communication betweena surface of a wellbore and a downhole location of a wellbore viaacoustic waveguide transfer. A first device can transmit an acousticsignal through a wellbore waveguide that is coupled with the firstdevice. The acoustic signal can transfer from the wellbore waveguide toa wellbore tubular through a contact between the wellbore waveguide andthe wellbore tubular. A second device can receive the acoustic signalvia the wellbore tubular that is coupled with the second device.

The present disclosure is described in relation to the subterranean welldepicted schematically in FIG. 1. Although FIG. 1 depicts a specificwellbore configuration, it should be understood by those skilled in theart that the present disclosure is equally well suited for use inwellbores having other orientations including vertical wellbores,slanted wellbores, multilateral wellbores and the like. Accordingly, itshould be understood by those skilled in the art that the use ofdirectional terms such as above, below, upper, lower, upward, downward,uphole, downhole and the like are used in relation to the illustrativeembodiments as they are depicted in the figures, the upward or upholedirection being toward the surface of the well, the downward or downholedirection being toward the bottom of the well. Also, even though FIG. 1depicts an onshore operation, it should be understood by those skilledin the art that the present disclosure is equally well suited for use inoffshore operations.

A well operation 100 can include a truck 140 which supports a power unit102, a tubing cabin 104 and a reel 106. An injector head unit 110positioned above the Earth's surface 120 can inject (or withdraw) awellbore tubular 108 from reel 106 into wellbore 138 through wellhead112. The wellbore 138 can include a casing 124 which can be cementedinto place in at least a portion of the wellbore 138. The wellbore 138can also include a production tubing 122 disposed within casing 124.

As the wellbore tubing 108 is lowered into wellbore 138, the wellboretubing 108 can experience various forces such as pressure, thermaland/or frictional forces. These forces can cause the normally straightconfiguration of the wellbore tubing 108 to become unstable which canresult in deformation, or buckling, of the wellbore tubing 108. Bucklingof the wellbore tubing 108 can take the form of sinusoidal buckling 130which can be followed by helical buckling 132. The buckling of wellboretubing 108, as well as deviations of wellbore 138, can create one ormore regions of physical, radial contact 126, 128 between the wellboretubing 108 and the production tubing 122 and/or the casing 124. Thenormal contact force imparted by the wellbore tubular 108 on theproduction tubing 122 and/or the casing 124 at the one or more regionsof contact 126, 128 can be directly related to the energy transfer ofthe acoustic signal disclosed below. To discuss the sinusoidal andhelical buckling of wellbore tubular 108 in greater detail, reference isnow made to FIGS. 2A-D.

FIG. 2A illustrates an example of sinusoidal buckling 200 of tubing in awellbore, such as sinusoidal buckling 130 of wellbore tubular 108 inwellbore 138. The sinusoidal buckling of a wellbore tubular 202 can forma two-dimensional sine wave in the tubing that is bounded by thewellbore casing 204. In general, sinusoidal buckling can occur before orat lower forces than helical buckling. As a non-limiting example,sinusoidal buckling of the tubing can occur when F_(p)<F_(b)<2√{squareroot over (2)}F_(p) according to equations (1), (2) and (3) below, whereF_(b) is the buckling force, F_(p) is the Paslay threshold force, F_(a)is the axial force, ρ_(i) is the internal pressure, A_(i) is theinternal radius of the tubing, ρ_(o) is the external pressure, A_(o) isthe external radius of the tubing, w_(c) is the casing contact load, EIis the pipe bending stiffness, r is the annular clearance, w_(e) is thedistributed buoyed weight of the casing, φ is the wellbore inclinationangle, and θ is the wellbore azimuth angle.

$\begin{matrix}{F_{b} = {{- F_{a}} + {\rho_{i}A_{i}} - {\rho_{o}A_{o}}}} & (1) \\{F_{p} = \sqrt{\frac{{EIw}_{c}}{r}}} & (2) \\{w_{c} = \sqrt{\left( {{w_{e}\sin \; \phi} + {F_{b}\frac{d\; \phi}{dz}}} \right)^{2} + \left( {F_{b}\sin \; \phi \frac{d\; \theta}{dz}} \right)^{2}}} & (3)\end{matrix}$

As shown in the cross-sectional view of FIG. 2B taken along line A′-A′in FIG. 2A, the wellbore tubular 202 can form one or more radial contactregions with casing 204 as it propagates through the wellbore. At eachcontact region a contact force can be imparted on the casing 204 by thewellbore tubular 202. As a non-limiting example, the average normalcontact force W_(n) for sinusoidal buckling can be calculated usingequation (4) below, where g is the gravitational force.

W _(n) =w _(e) g sin θ  (4)

FIG. 2C illustrates an example of helical buckling 210 of tubing in awellbore, such as helical buckling 132 of wellbore tubular 108 inwellbore 138. As a non-limiting example, helical buckling of the tubingcan occur when 2√{square root over (2)}F_(p)<F_(b) according toequations (1), (2) and (3) above. As depicted in the cross-sectionalview of FIG. 2D taken along the line B′-B′ in FIG. 2C, the helicalbuckling of wellbore tubular 212 can form a spiral or corkscrew withinthe casing 214 of the wellbore. In doing so, the wellbore tubular 212can create a nearly continuous radial contact region with casing 214throughout the length of the helical buckling. At each contact region orthroughout the continuous contact region, a contact force can beimparted on the casing 214 by the wellbore tubular 212. As anon-limiting example, the average normal contact force W_(n) for helicalbuckling can be calculated using equation (5) below.

$\begin{matrix}{W_{n} = \frac{{rF}_{b}^{2}}{4{EI}}} & (5)\end{matrix}$

Referring back to FIG. 1, to carry out various well operations such asdrilling, completion, workover, treatment, and/or production processes,one or more downhole tools unit 134 can be coupled with the wellboretubular 108 within wellbore 138. To enable communication between thesurface 120 and the one or more downhole tools unit 134, one or moresurface telemetry unit 114 and one or more downhole telemetry unit 136can be used. The one or more surface telemetry unit 114 can be locatedat surface 120 (e.g., directly on surface 120, at the top of wellbore138, within a proximity of wellhead 112, etc.) and can be coupled withwellhead 112, production tubing 122 and/or casing 124. Each surfacetelemetry unit 114 can receive power from power unit 102 via power line118 and can transmit or receive data to and from tubing cabin 104 viadata line 116, which can be a wired or wireless link. In addition, eachsurface telemetry unit 114 can include a transmitter, receiver and/ortransceiver for the purpose of communicating with one or more downholetelemetry unit 136. The one or more downhole telemetry unit 136 can becoupled with the wellbore tubular 108 within wellbore 138. Each downholetelemetry unit 136 can be within a corresponding downhole tools unit 134and/or communicatively coupled (wired or wirelessly) with one or moredownhole tools unit 134. Both the downhole telemetry unit 136 anddownhole tools unit 134 can receive power from downhole batteries,generators or any other downhole power source known in the art. Eachdownhole telemetry unit 136 can include a transmitter, receiver and/ortransceiver for the purpose of communicating with one or more surfacetelemetry unit 114.

To send data from the surface 120 to one or more downhole tools unit134, one or more surface telemetry unit 114 can generate and transmit anacoustic signal through a wellbore waveguide, such as the wellhead 112,production tubing 122 and/or casing 124. For example, the surfacetelemetry unit 114 can transmit an acoustic signal from the productiontubing 122, from the casing 124, or from the wellhead 112 which cantransfer the signal to the production tubing 122 and/or casing 124, andthe like. The acoustic signal can travel through the wellbore waveguideand can transfer to the wellbore tubular 108 at one or more contactregions 126, 128 between the wellbore tubing 108 and the productiontubing 122 and/or the casing 124. Once transferred, the acoustic signalcan travel through the wellbore tubular 108 and can be received by oneor more downhole telemetry unit 136. The downhole telemetry unit 136 canthen decode the acoustic signal and transmit the decoded signal to oneor more downhole tools unit 134, or can transmit the acoustic signal toone or more downhole tools unit 134 where it can be stored and/ordecoded.

When sending data from a downhole tools unit 134, the data can first bepassed to one or more downhole telemetry unit 136 which can thengenerate and transmit an acoustic signal through the wellbore tubular108. The acoustic signal can travel through the wellbore tubular 108 andcan transfer to a wellbore waveguide, such as the wellhead 112,production tubing 122 and/or casing 124, at one or more contact regionsbetween the wellbore tubing 108 and the wellbore waveguide. Oncetransferred, the acoustic signal can travel through the wellborewaveguide and can be received by one or more surface telemetry unit 114.The surface telemetry unit 114 can then decode the acoustic signal andtransmit the decoded signal to the tubing cabin 104, or can transmit theacoustic signal to the tubing cabin 104 where it can be stored and/ordecoded.

FIG. 3A illustrates a schematic diagram of an example telemetry system300 using acoustic waveguide transfer for communication from a surfacelocation to a downhole location. The system 300 can include atransmitter assembly 304 which can receive a raw data signal 302, forexample, from a user input, a processor, a computer-readable storagemedium, a tubing cabin and the like. The raw data signal 302 can be adigital signal and can include information, instructions or other datato be transmitted to one or more downhole tools units. The transmitterassembly 304 can be coupled with a wellbore waveguide 314 and can belocated at a surface location of a wellbore, such as at the top of thewellbore, on the surface surrounding the wellbore, within a proximity ofa wellhead associated with the wellbore and the like. The transmitterassembly can include a digital-to-analog converter 306, an amplifier308, a shunt 310 and a transmitter 312, although it should be understoodby those skilled in the art that the individual components of thetransmitter assembly 304 can be separated into one or moresub-assemblies separate from the transmitter assembly.

Upon receipt of the raw data signal 302, the transmitter assembly 304can convert the raw signal into an analog signal via digital-to-analogconverter 306. The analog signal can be amplified by an amplifier 308and can then be passed on to a transmitter 312. In some cases, a shunt310, such as a blocking inductor, can be included between the amplifier308 and the transmitter 312 to reduce energy consumption of thetransmitter.

To send the analog signal downhole, the transmitter 312 can transmit theanalog signal as an acoustic signal through a wellbore waveguide 314.The transmitter 312 can be a piezoelectric transmitter including one ormore piezoelectric elements and can be coupled with the wellborewaveguide 314. The wellbore waveguide 314 can be a static waveguide andcan include one or more of a wellhead, a wellbore casing, productiontubing and/or any other waveguide extending from the surface of awellbore towards a downhole location of the wellbore. The wellborewaveguide 314 can encapsulate at least a portion of a wellbore tubular316 and can have one or more regions of physical contact with thewellbore tubular 316. The one or more regions of contact can be regionsof radial contact between the wellbore waveguide 314 and the wellboretubular 316 which can be formed by deviations of the wellbore,sinusoidal buckling of the wellbore tubular, helical buckling of thewellbore tubular or otherwise. The wellbore waveguide 314 can alsoinclude one or more joints or discontinuities along its length which cancause one or more reflections of the acoustic signal.

When the acoustic signal is reflected, the reflected acoustic signal canconstructively and/or destructively interfere with the incident acousticsignal which can create passbands and/or stopbands within the wellborewaveguide 314. Reflections of the acoustic signal can be received by areceiver assembly at the surface of the wellbore (not shown) andanalyzed to determine differences between the transmitted acousticsignal and the reflected acoustic signal. The determined differences canbe used to determine, for example, an attenuation of the acousticsignal, a passband of the wellbore waveguide, a stopband of the wellborewaveguide, a standing wave ratio, a resonance and the like.

As the acoustic signal travels down the wellbore waveguide 314, it cantransfer from the wellbore waveguide to the wellbore tubular 316 viaacoustic waveguide transfer at the one or more regions of contactbetween the wellbore waveguide and wellbore tubular. The wellboretubular 316 can act as an acoustic waveguide and can be a dynamictubular such as coiled tubing or jointed tubing. The wellbore tubular316 can be a continuous medium to mitigate reflection and/or attenuationof the acoustic signal.

Once the acoustic signal is transferred (one or more times) to thewellbore tubular 316, it can travel down the wellbore tubular 316 to areceiver assembly 318. The receiver assembly 318 can be located at adownhole location of the wellbore and can be coupled with the wellboretubular 316 and/or one or more downhole tools units. The receiverassembly 318 can include a receiver 320 configured to receive theacoustic signal from the transmitter assembly 304 via the wellboretubular 316. The receiver 320 can be coupled with the wellbore tubular316 and can be any device capable of receiving the acoustic signal fromthe wellbore tubular, such as an accelerometer or a piezoelectricreceiver including one or more piezoelectric elements. Once the acousticsignal is received by receiver 320, it can be converted to a digitalsignal via analog-to-digital converter 322. A processor 324 can usememory 326 and a demodulator 328 to decode or demodulate the acousticsignal, for example, to determine instructions transmitted from thesurface. The demodulator 328 can be demodulating firmware stored onmemory 326 and executed by processor 324. The decoded acoustic signalcan be stored in memory 326 or can be output from the receiver assembly318 as output signal 330 which can be transmitted to, for example, oneor more downhole tools units.

FIG. 3B illustrates a schematic diagram of an example telemetry system350 using acoustic waveguide transfer for communication from a downholelocation to a surface location. The system 350 can include a transmitterassembly 354 which can receive a raw data signal 352, for example, froma processor, a computer-readable storage medium, one or more downholetools units and the like. The raw data signal 352 can be a digitalsignal and can include information, instructions or other data fromdownhole tools units and/or sensors to be transmitted to the surface ofa wellbore. The transmitter assembly 354 can be located at a downholelocation of a wellbore and can be coupled with one or more downholetools units and a wellbore tubular 364. The transmitter assembly caninclude a digital-to-analog converter 356, an amplifier 358, a shunt 360and a transmitter 362, although it should be understood by those skilledin the art that the individual components of the transmitter assembly354 can be separated into one or more sub-assemblies separate from thetransmitter assembly.

Upon receipt of the raw data signal 352, the transmitter assembly 354can convert the raw signal into an analog signal via digital-to-analogconverter 356. The analog signal can be amplified by an amplifier 358and can then be passed on to a transmitter 362. In some cases, a shunt360, such as a blocking inductor, can be included between the amplifier358 and the transmitter 362 to reduce energy consumption of thetransmitter.

To send the analog signal uphole, the transmitter 362 can transmit theanalog signal as an acoustic signal through a wellbore tubular 364. Thetransmitter 362 can be a piezoelectric transmitter including one or morepiezoelectric elements and can be coupled with the wellbore tubular 364.The wellbore tubular 364 can act as an acoustic waveguide and can be adynamic tubular such as coiled tubing or jointed tubing. The wellboretubular 364 can be a continuous medium to mitigate reflection and/orattenuation of the acoustic signal. The wellbore tubular 364 can alsohave one or more regions of physical contact with a wellbore waveguide366. The one or more regions of contact can be regions of radial contactbetween the wellbore tubular 364 and the wellbore waveguide 366 whichcan be formed by deviations of the wellbore, sinusoidal buckling of thewellbore tubular, helical buckling of the wellbore tubular or otherwise.

As the acoustic signal travels up the wellbore tubular 364, it cantransfer from the wellbore tubular to the wellbore waveguide 366 viaacoustic waveguide transfer at the one or more regions of contactbetween the wellbore tubular and wellbore waveguide. The wellborewaveguide 366 can be a static waveguide and can include one or more of awellhead, a wellbore casing, production tubing and/or any otherwaveguide extending from the surface of a wellbore towards a downholelocation of the wellbore. The wellbore waveguide 366 can encapsulate atleast a portion of a wellbore tubular 364. The wellbore waveguide 366can also include one or more joints or discontinuities along its lengthwhich can cause one or more reflections of the acoustic signal.

When the acoustic signal is reflected, the reflected signal canconstructively and/or destructively interfere with the incident acousticsignal which can create passbands and/or stopbands within the wellborewaveguide 366. Reflections of the acoustic signal can be received by areceiver assembly at the downhole location of the wellbore (not shown)and can be analyzed to determine differences between the transmittedacoustic signal and the reflected acoustic signal. The determineddifferences can be used to determine, for example, an attenuation of theacoustic signal, a passband of the wellbore waveguide, a stopband of thewellbore waveguide, a standing wave ratio, a resonance and the like.

Once the acoustic signal is transferred (one or more times) to thewellbore waveguide 366, it can travel up the wellbore waveguide 366 to areceiver assembly 368. The receiver assembly 368 can be located at asurface location of the wellbore and can be coupled with, for example, atubing cabin. The receiver assembly 368 can include a receiver 370configured to receive the acoustic signal from the transmitter assembly354 via the wellbore waveguide 366. The receiver 370 can be coupled withthe wellbore waveguide 366 and can be any device capable of receivingthe acoustic signal from the wellbore waveguide, such as anaccelerometer or a piezoelectric receiver including one or morepiezoelectric elements. Once the acoustic signal is received by receiver370, it can be converted to a digital signal via analog-to-digitalconverter 372. A processor 374 can use memory 376 and a demodulator 378to decode or demodulate the acoustic signal, for example, to determinedata transmitted from downhole. The demodulator 378 can be demodulatingfirmware stored on memory 376 and executed by processor 374. The decodedacoustic signal can be stored in memory 376 or can be output from thereceiver assembly 368 as output signal 380 which can be transmitted to,for example, a surface tubing cabin for analysis.

Although FIGS. 3A and 3B were described as separate systems forcommunication in one direction (i.e., surface to downhole and downholeto surface), it should be understood to those skilled in the art thatsuch systems can be readily combined to form a bidirectionalcommunication system using acoustic waveguide transfer. For example, thesurface and downhole locations of the wellbore can include both atransmitter assembly and a receiver assembly in a single unit (i.e., atransceiver) or as separate units. Further, each sub-component of thetransmitter and receiver assemblies of FIGS. 3A and 3B can be dividedinto one or more sub-assemblies which can be located at separatelocations. For example, a transmitter and/or receiver assembly at thesurface of a wellbore can be separated into sub-assemblies located atboth a wellhead associated with the wellbore and within a tubing cabinassociated with the wellbore. In addition, a transmitter and/or receiverassembly at a downhole location of a wellbore can be separated intosub-assemblies located within one or more downhole tools units and onthe wellbore tubular outside of the downhole tools unit.

FIG. 4A and FIG. 4B illustrate example computing systems for use withexample system embodiments. The more appropriate embodiment will beapparent to those of ordinary skill in the art when practicing thepresent technology. Persons of ordinary skill in the art will alsoreadily appreciate that other system embodiments are possible.

FIG. 4A illustrates a conventional system bus computing systemarchitecture 400 wherein the components of the system are in electricalcommunication with each other using a bus 405. System 400 can include aprocessing unit (CPU or processor) 410 and a system bus 405 that couplesvarious system components including the system memory 415, such as readonly memory (ROM) 420 and random access memory (RAM) 425, to theprocessor 410. The system 400 can include a cache of high-speed memoryconnected directly with, in close proximity to, or integrated as part ofthe processor 410. The system 400 can copy data from the memory 415and/or the storage device 430 to the cache 412 for quick access by theprocessor 410. In this way, the cache can provide a performance boostthat avoids processor 410 delays while waiting for data. These and othermodules can control or be configured to control the processor 410 toperform various actions. Other system memory 415 may be available foruse as well. The memory 415 can include multiple different types ofmemory with different performance characteristics. The processor 410 caninclude any general purpose processor and a hardware module or softwaremodule, such as module 1 432, module 2 434, and module 3 436 stored instorage device 430, configured to control the processor 4610 as well asa special-purpose processor where software instructions are incorporatedinto the actual processor design. The processor 410 may essentially be acompletely self-contained computing system, containing multiple cores orprocessors, a bus, memory controller, cache, etc. A multi-core processormay be symmetric or asymmetric.

To enable user interaction with the computing device 400, an inputdevice 445 can represent any number of input mechanisms, such as amicrophone for speech, a touch-sensitive screen for gesture or graphicalinput, keyboard, mouse, motion input, speech and so forth. An outputdevice 442 can also be one or more of a number of output mechanismsknown to those of skill in the art. In some instances, multimodalsystems can enable a user to provide multiple types of input tocommunicate with the computing device 400. The communications interface440 can generally govern and manage the user input and system output.There is no restriction on operating on any particular hardwarearrangement and therefore the basic features here may easily besubstituted for improved hardware or firmware arrangements as they aredeveloped.

Storage device 430 is a non-volatile memory and can be a hard disk orother types of computer readable media which can store data that areaccessible by a computer, such as magnetic cassettes, flash memorycards, solid state memory devices, digital versatile disks, cartridges,random access memories (RAMs) 425, read only memory (ROM) 420, andhybrids thereof.

The storage device 430 can include software modules 432, 434, 436 forcontrolling the processor 410. Other hardware or software modules arecontemplated. The storage device 430 can be connected to the system bus405. In one aspect, a hardware module that performs a particularfunction can include the software component stored in acomputer-readable medium in connection with the necessary hardwarecomponents, such as the processor 410, bus 405, output device 442, andso forth, to carry out the function.

FIG. 4B illustrates an example computer system 450 having a chipsetarchitecture that can be used in executing the described method andgenerating and displaying a graphical user interface (GUI). Computersystem 450 can be computer hardware, software, and firmware that can beused to implement the disclosed technology. System 450 can include aprocessor 455, representative of any number of physically and/orlogically distinct resources capable of executing software, firmware,and hardware configured to perform identified computations. Processor455 can communicate with a chipset 460 that can control input to andoutput from processor 455. Chipset 460 can output information to outputdevice 465, such as a display, and can read and write information tostorage device 470, which can include magnetic media, and solid statemedia. Chipset 460 can also read data from and write data to RAM 475. Abridge 480 for interfacing with a variety of user interface components485 can be provided for interfacing with chipset 460. Such userinterface components 485 can include a keyboard, a microphone, touchdetection and processing circuitry, a pointing device, such as a mouse,and so on. In general, inputs to system 450 can come from any of avariety of sources, machine generated and/or human generated.

Chipset 460 can also interface with one or more communication interfaces490 that can have different physical interfaces. Such communicationinterfaces can include interfaces for wired and wireless local areanetworks, for broadband wireless networks, as well as personal areanetworks. Some applications of the methods for generating, displaying,and using the GUI disclosed herein can include receiving ordereddatasets over the physical interface or be generated by the machineitself by processor 455 analyzing data stored in storage 470 or 475.Further, the machine can receive inputs from a user via user interfacecomponents 685 and execute appropriate functions, such as browsingfunctions by interpreting these inputs using processor 455.

It can be appreciated that systems 400 and 450 can have more than oneprocessor 410 or be part of a group or cluster of computing devicesnetworked together to provide greater processing capability.

Methods according to the aforementioned description can be implementedusing computer-executable instructions that are stored or otherwiseavailable from computer readable media. Such instructions can compriseinstructions and data which cause or otherwise configure a generalpurpose computer, special purpose computer, or special purposeprocessing device to perform a certain function or group of functions.Portions of computer resources used can be accessible over a network.The computer executable instructions may be binaries, intermediateformat instructions such as assembly language, firmware, or source code.Computer-readable media that may be used to store instructions,information used, and/or information created during methods according tothe aforementioned description include magnetic or optical disks, flashmemory, USB devices provided with non-volatile memory, networked storagedevices, and so on.

For clarity of explanation, in some instances the present technology maybe presented as including individual functional blocks includingfunctional blocks comprising devices, device components, steps orroutines in a method embodied in software, or combinations of hardwareand software.

The computer-readable storage devices, mediums, and memories can includea cable or wireless signal containing a bit stream and the like.However, when mentioned, non-transitory computer-readable storage mediaexpressly exclude media such as energy, carrier signals, electromagneticwaves, and signals per se.

Devices implementing methods according to these disclosures can comprisehardware, firmware and/or software, and can take any of a variety ofform factors. Such form factors can include laptops, smart phones, smallform factor personal computers, personal digital assistants, rackmountdevices, standalone devices, and so on. Functionality described hereinalso can be embodied in peripherals or add-in cards. Such functionalitycan also be implemented on a circuit board among different chips ordifferent processes executing in a single device.

The instructions, media for conveying such instructions, computingresources for executing them, and other structures for supporting suchcomputing resources are means for providing the functions described inthese disclosures.

Although a variety of information was used to explain aspects within thescope of the appended claims, no limitation of the claims should beimplied based on particular features or arrangements, as one of ordinaryskill would be able to derive a wide variety of implementations. Furtherand although some subject matter may have been described in languagespecific to structural features and/or method steps, it is to beunderstood that the subject matter defined in the appended claims is notnecessarily limited to these described features or acts. Suchfunctionality can be distributed differently or performed in componentsother than those identified herein. Rather, the described features andsteps are disclosed as possible components of systems and methods withinthe scope of the appended claims. Moreover, claim language reciting “atleast one of” a set indicates that one member of the set or multiplemembers of the set satisfy the claim.

STATEMENTS OF THE DISCLOSURE INCLUDE

Statement 1: A method, comprising: transmitting, by a first device, anacoustic signal through a wellbore waveguide that is coupled with thefirst device, transferring the acoustic signal from the wellborewaveguide to a wellbore tubular through a contact between the wellborewaveguide and the wellbore tubular, and receiving, by a second device,the acoustic signal via the wellbore tubular that is coupled with thesecond device.

Statement 2: The method according to Statement 1, wherein the firstdevice and the second device comprise at least one of an accelerometerand a piezoelectric element.

Statement 3: The method according to Statement 1 or 2, wherein thecontact is a radial contact formed by at least one of sinusoidalbuckling of the wellbore tubular and helical buckling of the wellboretubular.

Statement 4: The method according to any of Statements 1-3, furthercomprising: receiving, by the first device, a reflected acoustic signal,and determining one or more differences between the transmitted acousticsignal and the reflected acoustic signal.

Statement 5: The method according to any of Statements 1-4, wherein thewellbore waveguide encapsulates at least a portion of the wellboretubular.

Statement 6: The method according to any of Statements 1-5, wherein thewellbore waveguide is a static waveguide comprising casing or productiontubing, and wherein the wellbore tubular is a dynamic tubular comprisingcoiled tubing or jointed tubing.

Statement 7: The method according to any of Statements 1-6, wherein thefirst device is at a surface location of a wellbore, and wherein thesecond device is at a downhole location of the wellbore.

Statement 8: The method according to any of Statements 1-7, wherein theacoustic signal comprises instructions for a downhole tool, the methodfurther comprising: decoding the acoustic signal to produce a digitalsignal, and processing the digital signal via the downhole tool.

Statement 9: The method according to any of Statements 1-8, furthercomprising: transmitting, by the second device, a second acoustic signalthrough the wellbore tubular that is coupled with the second device,transferring the second acoustic signal from the wellbore tubular to thewellbore waveguide through the contact between the wellbore tubular andthe wellbore waveguide, and receiving, by the first device, the secondacoustic signal via the wellbore waveguide that is coupled with thefirst device.

Statement 10: The method according to any of Statements 1-9, wherein thesecond acoustic signal comprises data from a downhole tool.

Statement 11: A system, comprising: a wellbore waveguide, a wellboretubular having one or more regions of contact with the wellborewaveguide, a transmitter for transmitting an acoustic signal through thewellbore waveguide, wherein the transmitter is coupled with the wellborewaveguide at a surface location of a wellbore, and a receiver forreceiving the acoustic signal via the wellbore tubular, wherein thereceiver is coupled with the wellbore tubular at a downhole location ofthe wellbore.

Statement 12: The system according to Statement 11, wherein the one ormore regions of contact are formed by at least one of sinusoidalbuckling of the wellbore tubular and helical buckling of the wellboretubular.

Statement 13: The system according to Statement 11 or 12, wherein theacoustic signal comprises instructions for a downhole tool.

Statement 14: The system according to any of Statements 11-13, whereinthe wellbore waveguide is a static waveguide comprising casing orproduction tubing, and wherein the wellbore tubular is a dynamic tubularcomprising coiled tubing or jointed tubing.

Statement 15: The system according to any of Statements 11-14, furthercomprising: a second receiver for receiving a reflected acoustic signalvia the wellbore waveguide, wherein the second receiver is coupled withthe wellbore waveguide at a surface location of a wellbore, a processorcoupled with the second receiver for receiving the reflected acousticsignal, and a computer-readable storage medium having stored thereininstructions which, when executed by the processor, cause the processorto perform operations comprising: detecting one or more differencebetween the acoustic signal and the reflected acoustic signal.

Statement 16: A system, comprising: a wellbore waveguide, a wellboretubular having one or more regions of contact with the wellborewaveguide, a transmitter that transmits an acoustic signal through thewellbore tubular, wherein the transmitter is coupled with the wellboretubular at a downhole location of a wellbore, and a receiver thatreceives the acoustic signal via the wellbore waveguide, wherein thereceiver is coupled with the wellbore waveguide at a surface location ofthe wellbore.

Statement 17: The system according to Statement 11, wherein the one ormore regions of contact are formed by at least one of sinusoidalbuckling of the wellbore tubular and helical buckling of the wellboretubular.

Statement 18: The system according to Statement 11 or 17, wherein thewellbore waveguide encapsulates at least a portion of the wellboretubular.

Statement 19: The system according to any of Statements 11-18, whereinthe wellbore waveguide is a static waveguide comprising casing orproduction tubing, and wherein the wellbore tubular is a dynamic tubularcomprising coiled tubing or jointed tubing.

Statement 20: The system according to any of Statements 11-19, whereinthe acoustic signal comprises data from a downhole tool.

Statement 21: A system, comprising: a waveguide, a transmitter fortransmitting an acoustic signal through the waveguide, wherein thetransmitter is adapted to be coupled with the waveguide at a surfacelocation of a wellbore, and a receiver adapted to receive the acousticsignal via a wellbore tubular, wherein the receiver is adapted to becoupled with the wellbore tubular at a downhole location of thewellbore.

Statement 22: The system according to any of Statements 11-21, whereinthe wellbore tubular is adapted to receive the acoustic signal from thewaveguide through a contact between the waveguide and the wellboretubular.

Statement 23: The system according to any of Statements 11-22, whereinthe transmitter comprises one or more piezoelectric elements.

Statement 24: The system according to any of Statements 11-23, whereinthe receiver comprises at least one of an accelerometer and apiezoelectric element.

Statement 25: The system according to any of Statements 11-24, whereinthe wellbore tubular is a dynamic wellbore tubular.

We claim:
 1. A method, comprising: transmitting, by a first device, anacoustic signal through a wellbore waveguide that is coupled with thefirst device; transferring the acoustic signal from the wellborewaveguide to a wellbore tubular through a contact between the wellborewaveguide and the wellbore tubular; and receiving, by a second device,the acoustic signal via the wellbore tubular that is coupled with thesecond device.
 2. The method of claim 1, wherein the first device andthe second device comprise at least one of an accelerometer and apiezoelectric element.
 3. The method of claim 1, wherein the contact isa radial contact formed by at least one of sinusoidal buckling of thewellbore tubular and helical buckling of the wellbore tubular.
 4. Themethod of claim 1, further comprising: receiving, by the first device, areflected acoustic signal; and determining one or more differencesbetween the transmitted acoustic signal and the reflected acousticsignal.
 5. The method of claim 1, wherein the wellbore waveguideencapsulates at least a portion of the wellbore tubular.
 6. The methodof claim 1, wherein the wellbore waveguide is a static waveguidecomprising casing, wellhead or production tubing, and wherein thewellbore tubular is a dynamic tubular comprising coiled tubing orjointed tubing.
 7. The method of claim 1, wherein the first device is ata surface location of a wellbore, and wherein the second device is at adownhole location of the wellbore.
 8. The method of claim 7, wherein theacoustic signal comprises instructions for a downhole tool, the methodfurther comprising: decoding the acoustic signal to produce a digitalsignal; and processing the digital signal via the downhole tool.
 9. Themethod of claim 1, further comprising: transmitting, by the seconddevice, a second acoustic signal through the wellbore tubular that iscoupled with the second device; transferring the second acoustic signalfrom the wellbore tubular to the wellbore waveguide through the contactbetween the wellbore tubular and the wellbore waveguide; and receiving,by the first device, the second acoustic signal via the wellborewaveguide that is coupled with the first device.
 10. The method of claim9, wherein the second acoustic signal comprises data from a downholetool.
 11. A system, comprising: a wellbore waveguide; a wellbore tubularhaving one or more regions of contact with the wellbore waveguide; atransmitter for transmitting an acoustic signal through the wellborewaveguide, wherein the transmitter is coupled with the wellborewaveguide at a surface location of a wellbore; and a receiver forreceiving the acoustic signal via the wellbore tubular, wherein thereceiver is coupled with the wellbore tubular at a downhole location ofthe wellbore.
 12. The system of claim 11, wherein the one or moreregions of contact are formed by at least one of sinusoidal buckling ofthe wellbore tubular and helical buckling of the wellbore tubular. 13.The system of claim 11, wherein the acoustic signal comprisesinstructions for a downhole tool.
 14. The system of claim 11, whereinthe wellbore waveguide is a static waveguide comprising casing orproduction tubing, and wherein the wellbore tubular is a dynamic tubularcomprising coiled tubing or jointed tubing.
 15. The system of claim 11,further comprising: a second receiver for receiving a reflected acousticsignal via the wellbore waveguide, wherein the second receiver iscoupled with the wellbore waveguide at a surface location of a wellbore;a processor coupled with the second receiver for receiving the reflectedacoustic signal; and a computer-readable storage medium having storedtherein instructions which, when executed by the processor, cause theprocessor to perform operations comprising: detecting one or moredifference between the acoustic signal and the reflected acousticsignal.
 16. A system, comprising: a waveguide; a transmitter fortransmitting an acoustic signal through the waveguide, wherein thetransmitter is adapted to be coupled with the waveguide at a surfacelocation of a wellbore; and a receiver adapted to receive the acousticsignal via a wellbore tubular, wherein the receiver is adapted to becoupled with the wellbore tubular at a downhole location of thewellbore.
 17. The system of claim 16, wherein the wellbore tubular isadapted to receive the acoustic signal from the waveguide through acontact between the waveguide and the wellbore tubular.
 18. The systemof claim 16, wherein the transmitter comprises one or more piezoelectricelements.
 19. The system of claim 16, wherein the receiver comprises atleast one of an accelerometer and a piezoelectric element.
 20. Thesystem of claim 16, wherein the wellbore tubular is a dynamic wellboretubular.